The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
This invention relates to methods for servicing subterranean wells, in particular, fluid compositions and methods for operations during which the fluid compositions are pumped into a wellbore, make contact with subterranean formations, and block fluid flow through one or more pathways in the subterranean formation rock.
During the construction and stimulation of a subterranean well, operations are performed during which fluids are circulated in the well or injected into formations that are penetrated by the wellbore. During these operations, the fluids exert hydrostatic and pumping pressure against the subterranean rock formations. The formation rock usually has pathways through which the fluids may escape the wellbore. Such pathways include (but are not limited to) pores, fissures, cracks, and vugs. Such pathways may be naturally occurring or induced by pressure exerted during pumping operations.
During well construction, drilling and cementing operations are performed that involve circulating fluids in and out of the well. If some or all of the fluid leaks out of the wellbore during these operations, a condition known as “fluid loss” exists. There are various types of fluid loss. One type involves the loss of carrier fluid to the formation, leaving suspended solids behind. Another involves the escape of the entire fluid, including suspended solids, into the formation. The latter situation is called “lost circulation”, it can be an expensive and time-consuming problem.
During drilling, lost circulation hampers or prevents the recovery of drilling fluid at the surface. The loss may vary from a gradual lowering of the mud level in the pits to a complete loss of returns. Lost circulation may also pose a safety hazard, leading to well-control problems and environmental incidents.
During cementing, lost circulation may severely compromise the quality of the cement job, reducing annular coverage, leaving casing exposed to corrosive downhole fluids, and/or failing to provide adequate zonal isolation.
Lost circulation may also be a problem encountered during well-completion and workover operations, potentially causing formation damage, lost reserves and even loss of the well.
Even if lost circulation is a decades-old problem, there is no single solution that can cure all lost-circulation situations. Lost-circulation solutions may be classified into three principal categories: bridging agents, surface-mixed systems and downhole-mixed systems. Bridging agents, also known as lost-circulation materials (LCMs), are solids of various sizes and shapes (e.g., granular, lamellar, fibrous and mixtures thereof). They are generally chosen according to the size of the voids or cracks in the subterranean formation and, as fluid escapes into the formation, congregate and form a barrier that minimizes or stops further flow.
One of the major advantages of using fibers is the ease with which they can be handled. A wide variety of fibers is available to the oilfield made from, for example, natural celluloses, synthetic polymers, and ceramics, minerals or glass. Most are available in various shapes, sizes, and flexibilities. Fibers generally decrease the permeability of a loss zone by creating a porous web or mat that filters out solids in the fluid, forming a low-permeability filter cake that can plug or bridge the loss zones. Typically, solids with a very precise particle-size distribution must be used with a given fiber to achieve a suitable filter cake. Despite the wide variety of available fibers, the success rate and the efficiency are not always satisfactory.
An extensive discussion of lost circulation and techniques by which it may be cured is presented in the following publication: Daccord G, Craster B, Ladva H, Jones T G J and Manescu G: “Cement-Formation Interactions,” in Nelson E B and Guillot D (eds.): Well Cementing (2nd Edition), Schlumberger, Houston (2006) 191-219.
In the context of well stimulation, fluid loss is also an important parameter that must be controlled to achieve optimal results. In many cases, a subterranean formation may include two or more intervals having varying permeability and/or injectivity. Some intervals may possess relatively low injectivity, or ability to accept injected fluids, due to relatively low permeability, high in-situ stress and/or formation damage. When stimulating multiple intervals having variable injectivity it is often the case that most, if not all, of the introduced well-treatment fluid will be displaced into one, or only a few, of the intervals having the highest injectivity. Even if there is only one interval to be treated, stimulation of the interval may be uneven because of the in-situ formation stress or variable permeability within the interval. Thus, there is a strong incentive to evenly expose an interval or intervals to the treatment fluid; otherwise, optimal stimulation results may not be achieved.
In an effort to more evenly distribute well-treatment fluids into each of the multiple intervals being treated, or within one interval, methods and materials for diverting treatment fluids into areas of lower permeability and/or injectivity have been developed. Both chemical and mechanical diversion methods exist.
Mechanical diversion methods may be complicated and costly, and are typically limited to cased-hole environments. Furthermore, they depend upon adequate cement and tool isolation.
Concerning chemical diversion methods, a plethora of chemical diverting agents exists. Chemical diverters generally create a cake of solid particles in front of high-permeability layers, thus directing fluid flow to less-permeable zones. Because entry of the treating fluid into each zone is limited by the cake resistance, diverting agents enable the fluid flow to equalize between zones of different permeabilities. Common chemical diverting agents include bridging agents such as silica, non-swelling clay, starch, benzoic acid, rock salt, oil soluble resins, naphthalene flakes and wax-polymer blends. The size of the bridging agents is generally chosen according to the pore-size and permeability range of the formation intervals. The treatment fluid may also be foamed to provide a diversion capability.
In the context of well stimulation, after which formation fluids such as hydrocarbons are produced, it is important to maximize the post-treatment permeability of the stimulated interval or intervals. One of the difficulties associated with many chemical diverting agents is poor post-treatment cleanup. If the diverting agent remains in formation pores, or continues to coat the formation surfaces, production will be hindered.
A more complete discussion of diversion and methods for achieving it is found in the following publication: Provost L and Doerler N: “Fluid Placement and Diversion in Sandstone Acidizing,” in Economides M and Nolte K G (eds.): Reservoir Stimulation, Schlumberger, Houston (1987): 15-1-15-9.
Therefore, despite the valuable contributions of the prior art, there remains a need for improved materials and techniques for controlling the flow of fluids from the wellbore into formation rock. This need pertains to many operations conducted during both well construction and well stimulation.